Method and arrangement for treatment of fluid

ABSTRACT

A method utilizes the energy of water that flows out from a high-pressure reservoir. Water and hydrocarbons are separated in a down-hole separator and are brought separately to the seabed. In a first aspect the energy of the water is utilized to inject the water into an underground formation with a lower pressure. In a second aspect the energy is utilized to drive a turbine which in turn is driving a pump for pressurizing hydrocarbons. The invention utilizes a method and an arrangement to control the separator by control valves on the well head for each phase.

RELATED APPLICATIONS

The application is a National Stage of International Application No.PCT/NO01/00421, file Oct. 22, 2001, which published in the Englishlanguage and is an international filing of Norway Application No.20005318, filed on Oct. 20, 2000. Priority is claimed.

FIELD OF THE INVENTION

The present invention relates to downhole separation of hydrocarbons andwater followed by discrete (separate) transportation of the fluids to asubsea wellhead for further processing, especially avoiding use ofdownhole rotating machinery as far as possible. The invention relates ina first aspect to utilisation of the pressure energy in the water phasefor injection into an underground formation. In a second aspect theinvention relates to utilisation of the pressure energy of the waterphase or the hydrocarbon phase to power equipment on the seabed. Itrelates in a third aspect to a method of controlling the downholeseparator. In a fourth aspect it relates to a method and an arrangementof supplying gas for lifting the produced water to the wellhead.

BACKGROUND OF THE INVENTION

Capital and operational expenses of subsea developments, especially indeep waters, are high. Simple and reliable equipment is thereforeimportant. Well maintenance costs are high due to the high interventioncost. Reliability of all this equipment is therefore a key word forsuccess.

Flow assurance is of utmost importance for field economics. Water in thehydrocarbon stream is one of the frequent causes of flow relatedproblems. Removing water will reduce possible hydrate formation andallow using flow lines with smaller diameter at reduced cost. Powerneeded for pressure boosting will be reduced due to the lower bulk flowand density.

Water is almost always present in the rock formation where hydrocarbonsare found. The reservoir will normally produce an increasing portion ofwater with increase time. Water generates several problems for the oiland gas production process. It influences the specific gravity of thecrude flow by dead weight. It transports the elements that generatescaling in the flow path. It forms the basis for hydrate formation, andit increases the capacity requirements for flowlines and topsideseparation units. Hence, if water could be removed from the well floweven before it reaches the wellhead, several problems can be avoided.Furthermore, oil and gas production can be enhanced and oil accumulationcan be increased since increased lift can be obtained with removal ofthe produced water fraction.

A downhole hydrocyclone based separation system can be applied for bothvertically and horizontally drilled wells, and may be installed in anyposition. Use of liquid-liquid (oil-water) cyclone separation is onlyappropriate with higher water-cuts (typical with water continuouswellfluid). Water suitable for re-injection to the reservoir can beprovided by such a system. Cyclones are associated with purifying onephase only, which will be the water-phase in a downhole application.Using a multistage separation cyclone separation system, such asdescribed in pending Norwegian patent application NO 2000 0816 of thesame applicant will reduce water entrainment in the oil phase. However,pure oil will normally not be achieved by use of cyclones. Furthermore,energy is taken from the well fluid and is consumed for setting up acentrifugal field within the cyclones, thereby creating a pressure drop.

A downhole gravity separator is associated with a well speciallydesigned for its application. A horizontal or a slightly deviatedsection of the well will provide sufficient retention time and astratified flow regime, required for oil and water to separate due todensity difference.

Separation of water from the hydrocarbon flow is therefore important.Such separation can be done at the seafloor and downhole. The separationprocess is however proven to be much more efficient downhole than at theseafloor. Such separation is also done more efficiently in each wellbore than on the commingled well fluid from several wells. Downholeremoval of water from the hydrocarbon flow, giving a less dense column,will result in a higher pressure available at the seabed. This willresult in less need for pressure boosting for flow line transportation.Separation should therefore, if well conditions permit, rather bearranged downhole than subsea.

In copending Norwegian Patent Application No. 2000 1446 a system isdescribed, in which a downhole turbine/pump hydraulic converter is usedto inject the water into the formation to increase the pressure in theformation and thereby achieve more hydrocarbon output from thereservoir. This system is specially suitable for application in low tomedium pressure wells, in which the water injection can increase theoutput.

However, in high pressure wells it is usually not of major benefit toinject water. Thus, a different system is needed for such wells. Sinceall rotating machinery (pumps and compressors) are among the mostunreliable pieces of equipment of field developments, it is desirable toavoid such machinery downhole, where access and monitoring is difficult.In designing a system for exploitation of high pressure well it istherefor an object to avoid downhole rotating machinery as far aspossible.

The alternative, locating the equipment topside, i.e. on the platform,is, as mentioned above, not a very good solution either. This calls fora subsea location of at least a part of such equipment.

However, downhole separation has major benefits over topside or subseaseparation. This is due to the fact that the pressure gradient ofhydrocarbons is steeper than the pressure gradient of the water.Downhole separation of the reservoir fluid thus gives a higher pressureof the hydrocarbons at the seabed than the total reservior fluid. Ahigher pressure means that the hydrocarbons can be transported over afurther distance without additional pressure boosting or with lesspressure boosting, than in the case of separation at the seabed ortopside.

BRIEF SUMMARY OF THE INVENTION

The present invention is therefore allowing various combinations of adownhole separation system with subsea location of all rotatingmachinery. If artificial lift would be necessary, in particular late inthe well's lifetime, a gas lift system should be applied rather than adownhole pump.

Gas lift of the mixed well flow path is standard practice. In the wellknown method gas is injected in the well flow at some distance below thewell head, resulting in a reduction of the specific gravity of thecombined gas and well fluid. This further results in a reduction of theinflow pressure in the well bore and an increased flow rate. As thepressure is reduced higher up in the production tubing, furtherincreasing the gas volume, the gravity is even more reduced, helping theflow substantially. The gas is normally injected into the annulusthrough a pressure controlled inlet valve, into the production tubing ata suitable elevation. The elevation is mainly depending on available gaspressure.

However, it has not been suggested until now to use gas for artificiallift of the water. According to an aspect of the present invention thisis one way of ensuring a sufficient pressure of the water at the seabed,while avoiding pumps or the like downhole.

The pressure drop of well fluid during flow from the bottom hole to theseabed is determined by the following equation:Δp=ρ _(mix) gΔh+kρ _(mix) Q _(mix) ²  (1),wherein Δp is the pressure drop, ρ_(mix) is the density of the combinedphases of the well fluid, Δh is the depth from the seabed to the bottomhole, k is a constant (depending on inter alia the physical structuresof the flow line and Q_(mix) is the flow rate.

The first term (ρ_(mix)gΔh) is the static part of the pressure drop,while the second term (kρ_(mix)Q_(mix) ²) is the dynamic part of thepressure drop.

The density of the well fluid is determined by the following equation:ρ_(mix)=(ρ_(g) Q _(g)+ρ_(o) Q _(o)+ρ_(w) Q _(w))/(Q _(g) +Q _(o) +Q_(w))  (2),wherein ρ_(g), ρ_(o) and ρ_(w) are the densities of gas, oil and waterand Q_(g), Q_(o) and Q_(w) are the flow rates of gas, oil and water.

Since the densities of the three phases are increasing in the followingorder: ρ_(g), ρ_(o) and ρ_(w), a removal of the water from the wellfluid will reduce the density of the remaining phases and thereby reducethe pressure loss, i.e. the pressure gradient is steeper. Injection ofgas into the water will reduce the density of the combined phases(gas-water) and thereby reduce the pressure loss. However, a limitationon the amount of gas feasible for injection is limited by the secondterm of equation (1). Since the dynamic pressure drop is increasing byQ² the injection of gas above a certain amount will (at least in theory)increase the pressure drop. In other words: the use of gas forartificial lift will increase frictional pressure drop since the totalvolume flow increases with gas being brought back to the host. At longtie-back distances the net effect of using gas lift becomes low whengain in static pressure is reduced by increased dynamic pressure drop.However, downhole gas lift can be accomplished locally at the productionarea by separating and compressing a suitable rate of gas taken from thewell fluid and distributing the gas to the subsea wells for injection.This recycling of gas reduces the amount of gas flowing in the pipeline,compared to supplying gas from the host. The advantage of this can beutilized by increasing the production rate from the wells, reducingpipeline size or increasing capacity by having additional wellsproducing via the pipeline. In addition to this, gas lift at theriserbase will become more effective with this configuration.

The present invention therefor suggests in one aspect of the invention,applying downhole separation in combination with gas lift of theseparated water. As this water is lifted to surface it can be routed toan injection well or discharged to sea. If discharge to sea or a verylow pressurized discharge zone is allowed, the energy available in thewater flow path can be run through a turbine to typically power a pumpor a compressor.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will now be explained in further detail referring to theaccompanying drawings showing exemplifying embodiments for illustrationpurposes, in which:

FIG. 1 a illustrates a layout of downhole separation of fluid from anunderground formation, transportation of hydrocarbons and water to asubsea manifold, and subsequent injection of water into anotherformation according to a first embodiment of the invention.

FIG. 1 b illustrates a second embodiment of the present invention, whichis a variation of the embodiment of FIG. 1, but in which a turbine/pumphydraulic converter is provided in the manifold.

FIG. 1 c illustrates a third embodiment of the present invention, whichis a variation of the embodiment of FIG. 1 a, in which an electric pumpis provided for pressurising the water.

FIG. 2 a illustrates a layout of downhole separation of fluid from anunderground formation, transportation of hydrocarbons and water to asubsea manifold, and subsequent injection of water into anotherformation, using gas lift of the water according to a fourth embodimentof the invention.

FIG. 2 b illustrates a fifth embodiment of the invention, which is avariation of FIG. 2 a, in which an electric compressor is provided topressurise the gas.

FIG. 3 a illustrates a layout of downhole separation of fluid from anunderground formation, transportation of hydrocarbons and water to asubsea manifold, and subsequent injection of water into anotherformation, using gas lift of the water with gas supplied from a distantsource, according to a sixth embodiment of the invention.

FIG. 3 b illustrates a seventh embodiment of the present invention,which is a variation of FIG. 3 a, in which the water is also pressurisedby an electric pump before injection.

FIG. 4 a illustrates a layout of downhole separation of fluid from anunderground formation, transportation of hydrocarbons and water to asubsea manifold, and subsequent injection of water into anotherformation, using gas lift of the water, with gas in a closed circuit andde-gassing of the water, according to an eighth embodiment of theinvention.

FIG. 4 b illustrates a ninth embodiment of the present invention, whichis a variation of FIG. 4 a, in which an electric pump is provided forpressurising the water before injection.

FIG. 5 shows a diagram of the pressure gradients for water from arelatively newly developed high pressure formation.

FIG. 6 shows a diagram of the pressure gradients for water from adepleted formation.

DETAILED DESCRIPTION OF THE INVENTION

First FIGS. 5 and 6 will be explained for better understanding of thepressure conditions of a high pressure formation.

FIG. 5 shows a diagram of pressure gradients for water from a highpressure formation F, the reservoir pressure being denoted P_(FR).G_(WH) is the hydrostatic pressure gradient of water. Due to drawdown inthe formation (mainly caused by flow resistance of the pores in theformation) the bottom hole pressure P_(FB) is somewhat lower than P_(FR)Near the bottom of the well the formation fluid is separated into ahydrocarbon phase and a water phase. The hydrocarbons are brought to theseabed along a pressure gradient G_(H). The water is brought to theseabed along a pressure gradient G_(W). As clearly shown in FIG. 5, thepressure gradient G_(H) of the hydrocarbons is steeper than the pressuregradient G_(W) of water, which is parallel to G_(WH). Thus, thehydrocarbons will arrive at the seabed with a higher pressure P_(HS)than the water pressure P_(WS). The available pressure P_(HS) may beused for transportation or for power takeout.

Even though the water arrives at the seabed with a lower pressureP_(WS), the pressure of the water is substantially higher than thehydrostatic pressure P_(WHS) at the seabed level.

The water is to be injected into an injection zone I, which has apressure P_(I), equal to the hydrostatic pressure of water at the sameelevation. The water pressure P_(WS) may be too high for injectiondirectly. FIG. 5 show a choking of the water pressure along the arrow Ato a pressure P_(WC) which is subsequently used for injection. The arrowB illustrates the injection as the water pressure increases to apressure P_(WI). Due to the drawdown of the injection zone I, thepressure P_(WI) will have to be higher than the injection zone pressureP_(I). The arrow C illustrates the pressure decrease of the water as itpenetrates the injection zone.

In FIG. 6 the formation F has lost a substantial part of the initialpressure P_(FR), the depleted pressure is denoted P_(D). Due to drawdownof the formation the bottom hole pressure is reduced to P_(DB). Thewater gradient G_(W) illustrates the situation of freeflowing water tothe seabed. The resulting pressure P_(WSD) at the seabed issubstantially lower than the pressure P_(WS) if the water at the seabedwhen the formation F was at initial pressure. The pressure P_(WS) is toolow for the water to be injected into the injection zone I. The arrow Dshows a too low pressure difference.

The pressure gradient G_(WG) illustrates the situation when gas isintroduced to the water at an injection point IP downhole. This gradientG_(WG) is much steeper than the hydrostatic gradient G_(WH) of thewater. The water is thus arriving at a pressure of P_(WG) at the seabed.This pressure may be choked to a pressure P_(WGC), which is suitable forinjection, shown by the arrow E. The arrow H illustrates the injectioninto the injection zone I and the arrow J illustrates the drawdown ofthe injection zone.

FIG. 1 a illustrates a layout of a production manifold and wellaccording to a first embodiment of the present invention. The layoutillustrates production of fluid from an underground formation F andtransportation of the fluid to the subsea manifold.

Hydrocarbons (oil and in some cases gas) mixed with water is emanatingfrom the reservoir F flows via sand screens 1 into the well, and istransported in a tubing 2 to a downhole separator 3 where the waterphase and hydrocarbon phase are separated. The separator 3 may be ofgravity or centrifugal type. The water phase and hydrocarbons phase ofthe well fluid are transported to the wellhead 6 in separate flowchannels 4, 5. Typically the hydrocarbons will be routed to a productiontubing 4 whilst the water is routed to the annulus 5 formed between theproduction casing and the production tubing. Alternatively, in a dualcompletion system both phases will be brought to the seabed inindividual production tubes.

Using a dual function x-mas tree 6 facilitates production and control oftwo discrete flows from the well to the a subsea manifold system. Achoke valve 7 is provided after the x-mas tree 6 in the hydrocarbon flowline, and is used for controlling the well fluid production rate. Achoke valve 8 is provided after the x-mas tree in the water flow line,and is used for controlling the rate of water extracted from thedownhole separator 3.

Both fluid flows, hydrocarbons and water, are supplied to separateheaders 12, 17 in the manifold via a mechanical multibore connector 9 a.In the case the producing well is a satellite well rather than a wellplaced into a template, flowlines will connect the well to the manifold.The figure shows three producing wells connected to the manifold.

The hydrocarbon phase is routed into a first manifold header 12 via anisolation valve 10 a. The header is illustrated with a connector 14 anda full bore isolation valve 13 allowing hook-up to another manifold anda connector 15 at the opposite end, connecting to a flow line 16 fortransportation of the produced hydrocarbons to a host platform oranother receiver.

Subsea processing such as multiphase pressure boosting and gas liquidseparation may be incorporated into the described concept.

The water phase is routed into a second manifold header 17 via anisolation valve 11 a. The header is illustrated with a connector 19 anda full bore isolation valve 18 allowing hook-up to another manifold.

The water from the production wells is routed via an insulation valve 20to a third header 21 being in connection with one or several injectionwells (only one leading into a reservoir 28 is fully shown). Theinjection header 21 is illustrated connected to two injection wells,located within a subsea template, by single bore connectors 23 a, 23 b.The connector 23 a is shown connected to a choke valve 24, a wellhead25, a tubing 26 and an underground zone or reservoir 28. The water isdistributed to the wellhead 25 of the injection wells via the chokevalve 24 and routed via the tubing or casing 26 to a suitableunderground zone 28 for disposal.

Alternatively the formation 28 may be a hydrocarbon producing zone witha substantially lower pressure than the formation F, for sweep or forincreasing the pressure in the formation 28, to increase the hydrocarbonoutput.

The feasibility of this concept requires that the producing reservoir Fhas a sufficiently high pressure to overcome pressure drop related toinflow losses from the producing formation F into the production well,dynamical friction losses along the flow path and outflow losses fromthe bottom of the injection well into the disposal formation.

It also requires that the pressure of the separated water at the seabedis sufficiently high to overcome the counterpressure from the formation28, into which the water is to be injected. In case the pressure is notsufficiently high, a pump may be installed, which is to be explainedbelow.

FIG. 1 b illustrates a layout of a production manifold and wellaccording to a second embodiment of the present invention. The layout issimilar to FIG. 1 a, but with a turbine/pump hydraulic converter 31, 32installed in the manifold. This layout is applicable for a productionsituation whereby the water phase at the seabed has a higher pressurethan that which is required for injection. This available differentialpressure may be utilized for pressure boosting the hydrocarbon phase.

The concept is shown with a turbine 31 installed in second header 17 andmechanically connected to a multiphase pump 32 installed into the firstheader 12. A by-pass and utility system is not shown, but may bepresent. The water flowing into the second header 17 is driving theturbine 31 into rotation, the rotation is transmitted via a shaft to thepump 32, which in turn is pressurising the hydrocarbons. Thispressurising of the hydrocarbons will provide for a longer transportdistance for the hydrocarbons before additional pumps must be provided,and/or a larger through-put of hydrocarbons.

In the case of separation of the hydrocarbons into a gas phase and a oilphase downhole or at the seabed, the turbine may alternatively drive asingle phase pump or compressor to pressurise the oil flow or the gasflow.

After the pressurising of the hydrocarbons in the turbine/pump converter31, 32, the water is led to the third header 21 and injected, asexplained in connection with FIG. 1 a. The turbine/pump converter 31, 32must be carefully controlled so that not too much energy is taken out ofthe water. If this happens, it may prove difficult to inject the wateragainst the counterpressure in the formation 28. To facilitate thecontrol and regulation of the turbine/pump converter 31, 32, the turbine31 and/or the pump 32 may have variable displacement. A pressure sensor(not shown) may advantageously be installed in the second header 17after the turbine 32 to control the pressure of the water and adjust theturbine/pump converter 31, 32 according to this pressure.

A deep reservoir producing a light condensate will most likely havehigher pressure at the seabed than what is required for natural flow tothe receiver (i.e. host platform, floater etc.). Therefore, as analternative to providing a turbine in the second header 17, transportingwater, and a pump 32 in the first header 12, transporting hydrocarbons,the turbine may be provided in the first header 12 and the pump in thesecond header 17. In this case a turbine in the hydrocarbon flow canprovide required energy for re-injecting the produced water into theproducing reservoir, or formation 28 suitable for disposal. This isespecially advantageously if the water has a too low pressure forinjection and needs to be pressurized.

FIG. 1 c illustrates a layout of a production manifold and wellaccording to a third embodiment of the present invention. The layout issimilar to FIG. 1 a, but with the implementation of a retrievable speedcontrolled water injection pump 29 connected to the third header 21 ofthe subsea manifold by a multibore connector 30. The pump 29 isillustrated without details such as utility systems, recyclingarrangement and pressure equalizing valves. The produced water is fedfrom the second header 17, pressurized in pump 29 and discharged intothe header 21 for re-injection. In addition a flowline 34 supplyingadditional water for re-injection may be present as shown connected tothe third header 21 via a connector 33. The isolation valves 20, 35facilitate retrieval of the injection pump.

The feasibility of this concept requires that the water phase can bebrought from the formation to the suction side of the pump 29 with a netpositive suction head in excess of what is required to avoid cavitation.At high water depths the outlined concept is likely to be physicallypossible even though the producing reservoir is depleted far belowinitial or even below hydrostatic pressure.

FIG. 2 a illustrates a layout of a production manifold and wellaccording to a fourth embodiment of the present invention. The layout issimilar to FIG. 1 a, with an addition of a fourth header 49 and agas-liquid separator 40. The layout of FIG. 2 a is applicable in aproduction situation where artificial lift is utilized for producing thewater phase to the seabed with a sufficient high pressure for allowingthe water to be routed into the injection well(s) without pressureincrease at the seabed.

A branch line 37 a with an isolation valve 37 is connected to the firstheader 12. The branch line 37 is further connected to a gas-liquidseparator 40. From the gas-liquid separator 40 a gas outlet line 41 aand a liquid outlet line 38 a are extending. The gas outlet line 41 a isbranching into a gas return line 41 b and a gas supply line 42 a, whichis connected to a fourth header 49 through a control valve 42. The gasreturn line 41 b is connected to the liquid outlet line 38 a. The liquidoutlet line 38 a is further connected to the first header 12 via anisolation valve 38. In the first header 12, between the branch line 37 aand the liquid return line a by-pass valve 36 is provided.

The fourth header 49 is further connected to the x-mas tree 6 via anisolation valve 46, the multibore connector 9 a and a choke valve 47.From the x-mas tree 6 the gas is fed through a tubing 48 and into thewater pipeline 5.

Gas for lift is extracted from the produced hydrocarbon phase. Fluidfrom the header 12 is routed to the retrievable gas-liquid separator 40via the multibore mechanical connector 39 by opening the isolation valve37 and closing the by-pass valve 36. A control valve 41 regulated therate of gas extracted from the separator 40 with the objective ofmaintaining a suitable gas-liquid interface level within the separator40. A control valve 42 is adjusted for a suitable rate of gas to be fedto the gas injection header (fourth header) 49. The surplus gas is fedinto the gas return line 41 b, commingled with the liquid from theseparator 40 and returned to the hydrocarbon header (first header) 12via the isolation valve 38. The gas injection header (fourth header) 49is shown provided with a connector 44 and an isolation valve 45 at oneend. This facilitates a connection of the fourth header to othermanifolds or further wells.

Gas from the fourth header 49 is routed to the production x-mas tree 6,and to the wells connected to connectors 9 b and 9 c. A suitable rate isregulated by a choke valve 47. The depth of the injection point wheregas is commingled with the water is chosen with respect to available gaspressure. Because of the added gas, which has a substantial lowerdensity than the water, the overall bulk density of the column isreduced and the commingled water/gas flow will arrive at the wellheadwith a higher pressure than the water would have had without gas lift.In addition the gas will expand as the pressure is decreasing during thetravel to the well head, resulting in a further decrease of the density,and thus a further decrease in pressure drop. The gas utilized for liftwill follow the water phase into the second header and third header, andis in this discharged into the injection wells and the formation 28.

This production concept is illustrated with the total producedhydrocarbon flow. In alternative configurations a split flow orproduction from a single well may be used to provide gas for artificiallift of the water.

FIG. 2 b illustrates a similar layout to FIG. 2 a, but comprises in afifth embodiment also an electric compressor 49 b to pressurise the gasto improve lift capabilities. The compressor can be of centrifugal orpositive displacement type. The compressor 49 b is coupled into the gassupply line 42 a. Although some valves shown in FIG. 2 a are omitted inFIG. 2 b, these valves may be present in an actual design.

FIG. 3 a illustrates a layout of a production manifold and wellaccording to a sixth embodiment of the present invention. FIG. 3 aillustrates the concept of using gas for artificial lift of the waterproduced from the formation F and supplied to the subsea.

The manifold comprises in addition to the first header 12 and secondheader 17, an additional header 49, which corresponds to the fourthheader in the embodiments of FIGS. 2 a and 2 b, and thus is called thefourth header also with respect to the present embodiment. The fourthheader is in communication with the x-mas tree 6 via the isolation valve46, the multibore connector 9 a and the choke valve 47, in the same wayas illustrated in FIGS. 2 a and 2 b. From the x-mas tree the fourthheader is further communicating with a gas tubing 48, which is connectedto the water tubing 5, this also in the same way as in FIGS. 2 a and 2b.

The header is also connected to a gas supply line 50 via a connector 51and an isolation valve 52. The gas supply line may be a serviceumbilical.

The gas supply line 50 is supplying gas from a distant source, e.g. agas producing well, which is fed into the fourth header 49 via theconnector 51 and the isolation valve 52 and further into the watertubing 5 via the isolation valve 46, the connector 9 a, the choke valve47, the x-mas tree 6 and the gas tubing 48.

In comparing the layout of FIG. 3 a with the layout of, e.g. FIG. 2 b,it is also evident that the second and the third headers are combinedinto one header divided by an isolation valve 20. This configuration iscompletely equivalent with the configuration of FIG. 2 b.

In other respects the embodiment of FIG. 3 a is functioning the same wayas in FIGS. 2 a and 2 b.

FIG. 3 b is illustrating a layout of a seventh embodiment of the presentinvention, which is similar to the embodiment of FIG. 3 a, but with anaddition of an electric water pump 53 for pressurising water forinjection. The pump 53 is coupled into the connection between the secondheader 17 and the third header 21.

The produced water with gas used for artificial lift can be re-injectedby use of the subsea speed controlled multiphase pump 53. The pump isshown retrievable and integrated into the subsea manifold between theproduced water header 17 and the water injection header 21 by amechanical connector 30.

This embodiment is applicable when the pressure inherent in the water atthe seabed and the lift created by the gas insertion are not enough toinject the water into the formation 28 against the counter pressure inthis formation. The pump 53 will create the extra pressure needed.

FIG. 4 a illustrates a layout of an eighth embodiment, which in somerespects is similar to the embodiment of FIG. 2 b. However, in thisembodiment the gas is separated from the water.

The embodiment of FIG. 4 a comprises a first header 12 for conductinghydrocarbons, a second header 17 for conducting water from the formationF and a fourth header 49 for conducting gas for gas lift. A third headeris not illustrated, but may be present as appropriate.

The second header is connected to a gas-liquid separator 54 via anisolation valve 20 and a connector 58. The gas-liquid separator 54 has agas outlet line 54 a, a liquid outlet line 54 b and a gas supplementline 54 c. The gas outlet line is connected to the fourth header via acompressor 57. The liquid outlet line is connected to the connector 23 aand from this to the well leading into the formation 28. The gassupplement line is connected to a gas supply line 50 via an isolationvalve 55.

FIG. 4 a illustrates the concept of de-gassing the produced water at theseabed and re-cycling the gas for artificial lift of the produced water.The produced water containing the gas lift gas is routed from the secondheader 17 to the gas-liquid separator 54 via the multibore connector 58.The gas extracted from the separator 54 is pressurized in the compressor57 and discharged into the fourth header (gas lift header) 49 via theconnector 58, and further distributed to the producing wells, and asillustrated into the water tubing 5 via the gas tubing 48. The de-gassedwater is fed via the liquid outlet line 54 b and the connectors 58 and23 a to the water injection well and the formation 28. The gas regainedfrom the water is again fed into the fourth header 49. The separator 54and compressor 57 with interconnecting piping is shown as a retrievableunit.

For make-up and for initial start-up gas may be supplied via the gassupply line by opening the isolation valve 55. The line 50 may be aservice umbilical line leading from a distant source or a line leadingfrom a de-gasser (not shown), extracting gas from the producedhydrocarbons.

In case some of the gas is lost during this process, or in case more gasthan needed is retrieved from the water, gas may be supplied orwithdrawn from the gas supply line 50 by opening the isolation valve 55.

The water may also optionally be discharged to the surrounding sea,instead of or supplemental to disposal in an underground formation,provided it has sufficient pressure, and that de-oiling cyclones areutilized to meet required oil-in-water entrainment requirement.

FIG. 4 b illustrated in a ninth embodiment a similar concept asdescribed in FIG. 4 a, with the addition of a single phase waterinjection pump 60 integrated into the subsea manifold by a multiboreconnector 59. This pump 60 has the same function as the pump 53 of theembodiment in FIG. 3 b. i.e. to boost the pressure of the water beforeinjection if the pressure on the suction side of the pump is too low forthe water to be injected by its inherent pressure.

All the described production alternatives can be enhanced as required toinclude subsea processing equipment for gas-liquid separation, furtherhydrocarbon-water separation by use of electrostatic coalescing, singlephase liquid pumping, single phase gas compression and multiphasepumping. In case of subsea gas-liquid separation, gas may be routed toone flowline whilst the liquid is routed to the other. Any connector maybe of horizontal or vertical type. Return and supply lines may be routedthrough a common multibore connector or be distributed using independentconnectors. As an alternative to inject the water into a different wellthan the production well, the water may be injected into the productionwell and disposed of in a formation at a higher elevation, with lowpressure.

Instead of injecting the water into a formation, the water may,according to regulations, purity of the water, environmental conditionsand available polishing equipment, be disposed of to seawater. To beable to do this the water must be de-gassed and optionally polished toremove environmentally hazardous compounds.

Choke valves may be located on the x-mas tree as shown in attachedfigures, but can also be located on the manifold. The valves may ifrequired be independent retrievable items. Subsea choke valves arenormally hydraulic operated but may be electrical operated forapplication where a quick response is needed.

Electrically operated pumps are not illustrated in attached figures withutility systems for re-cycling, pressure compensation and refill. Onepump only is shown for each functional requirement. However, dependingon flowrates, pressure increase or power arrangement with several pumpsconnected in parallel or series may be appropriate.

The present invention also provides for any working combination of theembodiments shown herein. The invention is limited only by the enclosedclaims and equivalents thereof.

1. A method of producing reservoir fluid from a hydrocarbon containingunderground reservoir, comprising the following steps: in an oil wellcomprising a subsea wellhead and wellbore extending into a subseaunderground reservoir, said subsea well connected to a flowline to thesea surface; separating reservoir fluid downhole in said wellbore intoat least a hydrocarbon phase and a water phase, bringing the hydrocarbonphase and the water phase separately to said subsea wellhead after beingseparated, injecting said water phase into another wellbore through anassociated second subsea wellhead and utilizing at least partly thepressure in said water phase.
 2. The method according to claim 1,wherein the water phase is free-flowing from the production wellheadinto said another wellbore.
 3. The method according to claim 1, whereinthe water phase is pressurized by a pump located at the seabed beforebeing injected into said another wellbore.
 4. The method according toclaim 1 of producing reservoir fluid from a hydrocarbon containingunderground reservoir, comprising the following steps: utilizing atleast partly the pressure in at least one of the said phases to power atleast one component located at the seafloor chosen from the group ofcomponents consisting of turbines, pumps, compressors and separators. 5.The method according to claim 4, wherein energy from the water phase isutilized in at least one turbine which in turn powers at least one pump,wherein said pump boosts the pressure of the hydrocarbon phase.
 6. Themethod according to claim 4, wherein said hydrocarbon phase powers atleast one turbine, which in turn powers at least one pump, and said pumpboosts the pressure of said water phase before injection of said waterphase into another wellbore.
 7. The method according to claim 4, whereinpressure from said water phase powers a compressor which in turnpressurizes gas.
 8. The method according to claim 4, wherein pressurefrom said water phase powers at least one gas-liquid separator.
 9. Themethod according to claim 8, further comprising the steps of degassingsaid water phase, and disposing of said water phase to seawater.
 10. Themethod of claim 1 of producing reservoir fluid from a hydrocarboncontaining underground reservoir comprising: leading said hydrocarbonphase through a first control valve; leading said water phase through asecond control valve; said first and second control valves being locatedat seabed, measuring at least one of parameter chosen from the group ofparameters consisting of: a separator interface level, a flow-split, adifferential pressure across said separator and a phase purity; andregulating at least one of said control valves as a function of said atleast one parameter to increase or decrease the flow rate ofhydrocarbons or water from said separator, to maintain said at least oneparameter within predefined limits.
 11. A method of producing reservoirfluid from a subsea, hydrocarbon containing underground reservoir,comprising the following steps: in an oil well comprising a subseawellhead and wellbore extending into a subsea underground reservoir,said subsea wellhead connected to a flowline to the sea surface;separating reservoir fluid downhole in said wellbore into at least ahydrocarbon phase and a water phase, bringing the hydrocarbon phase andthe water phase separately to said subsea wellhead after beingseparated, using a gas phase for artificial lift of said water phase tosaid first subsea wellhead, injecting said water phase into anotherwellbore through an associated second subsea wellhead and utilizing atleast partly the inherent pressure in said water phase.
 12. The methodof producing reservoir fluid of claim 11, said using gas for artificiallift of said water phase comprising: providing a gas phase with a higherpressure than said water phase at a downhole injection level; andinjecting said gas phase into said water phase at said injection level,thereby using said gas phase for artificial lift of said water phase.13. The method according to claim 12, wherein said gas phase forartificial lift is provided by separation of gases from said hydrocarbonphase in a subsea separator.
 14. The method according to claim 13,farther comprising compressing said gas phase before said gas phase isinjected into said water phase.
 15. The method according to claim 12,wherein said gas phase for artificial lift is provided by separatingsaid gas phase from said water phase at the seabed.
 16. The methodaccording to claim 11, wherein said gas phase for artificial lift issupplied from a distant source.
 17. The method according to claim 11,farther comprising injecting said water phase together with said gasphase used for artificial lift into said another wellbore and hence intoan underground formation.
 18. The method of producing reservoir fluidaccording to claim 12, said injecting said water phase into anotherwellbore comprising pressurizing said water phase with a pump.
 19. Asystem for producing reservoir fluid from a subsea, hydrocarboncontaining underground reservoir, comprising: a subsea wellhead andwellbore extending into a subsea underground reservoir; a flowlineconnecting said wellhead to the seasurface; a hydrocarbon-waterseparator located downhole in said wellbore and having at least onehydrocarbon outlet for hydrocarbon and at least one water outlet forwater, each coupled to said wellhead and hense to a respectivehydrocarbon line and water line; and a subsea means for injection ofsaid water through said water line into another associated wellborecoupled to the wellhead.
 20. The system according to claim 19, furthercomprising a pump coupled to said subsea means for injection, forpressurizing said water before injection of said water into saidassociated wellbore.
 21. The system according to claim 19, wherein saidwater line is coupled to a turbine, and said hydrocarbon line is coupledto a pump, said turbine being coupled to said pump.
 22. The systemaccording to claim 19, wherein said water line is coupled to a pump,said hydrocarbon line is coupled to a turbine, and said the turbine iscoupled to said pump.
 23. The system according to claim 19, wherein saidwater line is coupled to a turbine, and said turbine is coupled to acompressor for pressuring gas.
 24. The system according to claim 19,wherein said water line is coupled to a separator configured to degassaid water.
 25. The system for producing reservoir fluid according toclaim 19, comprising: a hydrocarbon tubing between said hydrocarbonoutlet and said wellhead; a water tubing between said water outlet andsaid wellhead; first and second control valves disposed at saidwellhead; said hydrocarbon tubing being coupled to said first controlvalve, said water tubing being coupled to said second control valve; ameasuring means for measuring at least one parameter chosen from thegroup of parameters consisting of: separator interface level,flow-split, differential pressure across the separator and phase purity;a regulating means for regulating said first and/or said second controlvalves to control a flow rate from said separator, to maintain said atleast one parameter within predefined limits.
 26. A system for producingreservoir fluid from a subsea, hydrocarbon containing undergroundreservoir, comprising: a downhole hydrocarbon-water separator in asubsea wellbore; a subsea wellhead; a hydrocarbon tubing between saidseparator and said wellhead; a water tubing between said separator andsaid wellhead; a hydrocarbon line coupled to said hydrocarbon tubing atsaid wellhead; a water line coupled to said water tubing at saidwellhead; a gas line coupled to a gas tubing at said wellhead, and saidgas tubing being coupled to the water tubing at a downhole injectionpoint, for injection of gas to achieve artificial lift of water; saidwater line coupled to an associated wellhead and wellbore.
 27. Thesystem according to claim 26, further comprising an additional separatorcoupled to said hydrocarbon line for separating gas from hydrocarbons.28. The system according to claim 26, further comprising an additionalseparator coupled to said water line, for separating gas from the water.29. The system according to claim 28, further comprising a compressorcoupled to said gas line, for compressing said gas.
 30. The systemaccording to claim 26, further comprising a gas supply line coupled tosaid gas line.